Gas Fracture Injection to Overcome Retrograde Condensation in Gas Wells

ABSTRACT

Disclosed is a well configuration and method of forming the configuration and producing hydrocarbons from the configuration. In one embodiment, multiple fractures are formed from a wellbore in a subterranean hydrocarbon gas formation. One fracture is filled with material to create a flow barrier that modifies the flow pattern of at least one fluid within the subterranean hydrocarbon formation. Also disclosed is the process of injecting a Dew Point altering gas into the formation on one side of the barrier and producing a mixture of formation gas and injected gas from the fractures on the other side of the barrier.

CROSS REFERENCE TO RELATED APPLICATIONS

U.S. patent application entitled, “Methods Relating to Modifying FlowPatterns Using In-Situ Barriers,” Serial Number 720736 to Soliman etal., filed Mar. 10, 2010, U.S. Publication 20110220359, published Sep.15, 2011.

BACKGROUND

The present invention relates generally to hydrocarbon production and,more particularly, to a method of increasing hydrocarbon production ingas well by forming an in-situ barrier and by injecting a gas on oneside of the barrier to mix with and modify the Dew Point Pressure of theresulting mixture of reservoir gas and injected gas.

In some subterranean formations, gas production with low to moderatematrix permeability to gas and high gas specific gravity suffers fromretrograde condensation effects. As used in the well context, the term“retrograde condensation” refers to the formation of liquid hydrocarbonsin a gas reservoir, which occurs as the pressure in the reservoirdecreases below Dew Point Pressure during production.

As used herein, the term “Dew Point Pressure” is the gas pressure atwhich a system is at its Dew Point, that is, the pressure at a giventemperature at which the first dew or liquid phase occurs. The name“retrograde” (meaning to retreat or go back) is used herein to describea system where, at a given temperature, lowering pressure causescondensation. Condensation in gas production is sometimes described as“liquid drop out.” The term “condensate banking” refers to the formationof liquids with the gas in the formation, i.e., rock matrix, in theproducing intervals around the wellbore. With the retrogradecondensation, the percentage of liquid begins to increase as pressuredecreases and then the percentage of liquid decreases with furtherpressure declines. Condensate backing reduces the apparent permeabilityof the matrix and reduces the total production rate for a given flowingpressure.

One method used by the industry to reduce the effects of retrograde gascondensation in the rock matrix around the wellbore is to maintainreservoir pressure above the Dew Point Pressure by injecting a fluid orgas to replace the volume produced from the formation. However, atreasonable production rates reservoir pressure cannot be maintained andcondensate banking will occur in the rock matrix near the producingintervals as the pressure drops below the Dew Point Pressure.

Another method used in the industry to mitigate retrograde condensationinvolves flooding the reservoir with a miscible gas, such as methane orCO₂. The methane gas is a byproduct of “stripping” the condensate fromthe produced gas. When these gases are mixed with the reservoir gas, theresulting gas mixture can result in a more phase stable gas mixture witha significantly lower Dew Point pressure.

Prior art well configurations used to deal with retrograde condensatereservoirs involve drilling separate producer and injection wells. Themost common pattern is called a 5-spot pattern with the injection wellsurrounded by four producing wells. An injection fluid, such as methanegas, is injected from the center well.

SUMMARY

The present invention relates generally to hydrocarbon production and,more particularly, to a method of increasing hydrocarbon production ingas well by maintaining the reservoir gas at or above its Dew PointPressure during production.

In one embodiment, an in-situ barrier is formed and gas produced fromthe formation on one side of the barrier while Dew Point lowering gas isinjected on the other side of the barrier to mix with and modify the DewPoint of the resulting mixture of reservoir gas and injected gas.

The methods of forming in-situ barriers as described in U.S. Pat. No.8,104,535 to Sierra et al., issued Jan. 31, 2012, entitled “Method ofImproving Waterflood Performance Using Barrier fractures and InflowControl Devices” and U.S. application, entitled “Methods Relating toModifying Flow Patterns Using In-Situ Barriers,” Serial number 720736 toSoliman et al., filed Mar. 10, 2010, U.S. Publication 20110220359,published Sep. 15, 2011, now U.S. Pat. No. 8,104,535, which areincorporated herein by reference for all purposes.

In an embodiment of the method, the method comprises: forming an in-situbarrier at one point along the wellbore; injecting methane or carbondioxide gas on one side of the barrier to mix with and raise the DewPoint of the resulting mixture of reservoir gas and injected gas; andflowing the mixture of reservoir gas and injected gas into the wellboreon the opposite side of the barrier.

In an embodiment, a method comprises: forming a horizontally extendingwellbore in a hydrocarbon gas bearing formation; forming an in-situbarrier at one point along the wellbore; injecting a gas on one side ofthe barrier to mix with and modify the Dew Point of the resultingmixture of reservoir gas and injected gas; and flowing the mixture ofreservoir gas and injected gas into the wellbore on the opposite side ofthe barrier.

In an embodiment, a method comprises: forming an in-situ barrier at onepoint along the wellbore; injecting a gas on one side of the barrier tomix with and raise the Dew Point Pressure of the resulting mixture ofreservoir gas and injected gas; and flowing the mixture of reservoir gasand injected gas into the wellbore on the opposite side of the barrierand selectively controlling the flow of the hydrocarbon mixture into thewellbore at the plurality of locations to maintain the produced gasmixture at a pressure above the Dew Point Pressure.

In one embodiment, valves are present that control flow based on or as afunction of the phase of the hydrocarbon flow. For example, valves canbe provided that limit the flow of hydrocarbon in liquid phase whilepermitting the flow of hydrocarbon in gaseous phase into the wellbore.At a given rate of gas production, if the formation pressure around theproducing wellbore begins to approach the Dew Point Pressure and liquidsbegin to be present in the production, the valves would further restrictflow into the wellbore to maintain the produced gas at a pressure aboveits Dew Point Pressure.

In another example, valves are present that limit the flow ofhydrocarbon in gaseous phase, while permitting the flow of hydrocarbonin liquid phase into the wellbore. Valves can be installed in thewellbore that limit the flow of hydrocarbon in dry gaseous phase whilepermitting the flow of hydrocarbon in gases in liquid rich phase intothe wellbore. In this manner, the valves can function to prevent thecycling of injected gas around the barrier and back into the wellbore,while producing formation gases in liquid rich phase.

In another embodiment, a method of producing hydrocarbons from asubterranean formation containing hydrocarbons in a gaseous phase,comprising providing a wellbore in to the subterranean hydrocarbonfluid-bearing formation; providing an in-situ barrier, wherein thein-situ barrier is disposed within the subterranean formation andmodifies the flow pattern of at least one fluid within the subterraneanformation; injecting a hydrocarbon fluid in gaseous state from thewellbore into the formation from one side of the barrier to mix with theformation fluids to form a hydrocarbon mixture with a lower Dew Pointthan the formation hydrocarbon; and flowing the hydrocarbon mixture intothe wellbore on the other side of the barrier.

In a further embodiment, a method of producing hydrocarbons from asubterranean formation containing hydrocarbons in a gaseous phase,comprising providing a cased horizontal wellbore extending into thesubterranean hydrocarbon fluid-bearing formation; providing an in-situbarrier adjacent the toe of the wellbore, wherein the in-situ barrier isdisposed within the subterranean formation and modifies the flow patternof at least one fluid within the subterranean formation; injecting ahydrocarbon fluid in gaseous state from the wellbore into the formationfrom the toe side of the barrier to mix with the formation fluids toform a hydrocarbon mixture with a lower Dew Point Pressure than theformation hydrocarbon; and flowing the hydrocarbon mixture into thewellbore at a plurality of spaced-apart locations on the heel side ofthe barrier and controlling the flow of the hydrocarbon mixture into thewellbore at the plurality of locations in response to the phase ofhydrocarbon in gaseous flowing into the wellbore.

In still another embodiment, a cased horizontal wellbore in subterraneanif provided wherein the formation surrounding the wellbore is fracturedat a plurality of spaced locations along the wellbore. A barrier isformed in one fracture located between two fractures.

The features and advantages of the present invention will be apparent tothose skilled in the art. While numerous changes may be made by thoseskilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention. The drawings are incorporated into and form a part of thespecification to illustrate at least one embodiment and example of thepresent invention. Together with the written description, the drawingsserve to explain the principles of the invention. The drawings are onlyfor the purpose of illustrating at least one preferred example of atleast one embodiment of the invention and are not to be construed aslimiting the invention to only the illustrated and described example orexamples. The various advantages and features of the various embodimentsof the present invention will be apparent from a consideration of thedrawings in which:

FIG. 1 is a well diagram, illustrating a conventional horizontal wellcompletion of a retrograde condensate gas reservoir, showing condensatebanking during production;

FIG. 2 is a cross section view of the well completion of FIG. 1,illustrating the condensate banking region around the wellbore;

FIG. 3 illustrates an embodiment an improved horizontal well completion,utilizing a barrier around the wellbore according to the presentinvention; and

FIG. 4 illustrates an alternative embodiment of an improved, horizontalwell completion, utilizing a barrier around the wellbore and inflowcontrol devices, according to the present invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention relates generally to hydrocarbon production, andmore particularly to a method of increasing hydrocarbon production ingas wells by forming an in-situ barrier and by injecting a gas on oneside of the barrier to mix with and modify the Dew Point of theresulting mixture of reservoir gas and injected gas.

The present invention provides improved methods, systems, and materialsfor modifying the flow pattern in a reservoir and reducing the effectsof retrograded condensation. The methods, systems, and materials can beused in either vertical, deviated or horizontal wellbores, inconsolidated and unconsolidated formations, in “open-hole” and/or underreamed completions, as well as in cased wells. If used in a casedwellbore, the casing may be perforated to provide for fluidcommunication between the wellbore and the subterranean formation. Theterm “vertical wellbore” is used herein to mean the portion of awellbore to be completed which is substantially vertical or deviatedfrom vertical in an amount up to about 15°. The term “horizontalwellbore” is used herein to mean the portion of a wellbore to becompleted which is substantially horizontal or at an angle from verticalin the range of from about 75° to about 105°. All other angularpositioning relates to a deviated or inclined wellbore. Since thepresent invention is applicable in horizontal and inclined wellbores,the terms “upper and lower” and “top and bottom” as used herein arerelative terms and are intended to apply to the respective positionswithin a particular wellbore, while the term “levels” is meant to referto respective spaced positions along the wellbore. In the presentdescription, the terms “upper,” “top,” and “above” refer to the portionof a wellbore nearer to the surface or wellhead while the terms “lower,”“bottom,” and “below” refer to the portion of a wellbore further fromthe surface or wellhead, irrespective of the true vertical depth of anyportion of the wellbore. The term “toe” is used to describe the lower orbottom portion of a horizontally extending wellbore. The term “heal” isused to refer to the upper or top portion of the horizontal extendingportion of the wellbore. In the description and drawings, the wellboresare illustrated in diagram or schematic form, wherein the proportionsare not intended to represent the actual wellbore size. For example,wellbores can extend horizontally for miles in a hydrocarbon formationand have hundreds of perforations and fractures.

Referring initially to FIG. 1, there is illustrated in diagram form, aconventional, horizontally extending wellbore 100 located in ahydrocarbon gas bearing subterranean formation 102. The wellbore 100 iscased 104 and the casing perforated 106 at spaced areas spaced along theextent of the casings in the formation 102. The perforations can beformed in any conventional manner, such as by using explosives,mechanical cutting, or jetting. The lower end of the casing is blockedor closed off by a bridge plug 108.

The casing interior pressure of the gas flowing in the casing isdesignated as P_(wf), and the reservoir gas pressure is designated asP_(rp). The reservoir gas has a Dew Point pressure of P_(dp). In theillustrated embodiment P_(rp)>P_(dp)>P_(wf), as illustrated in FIG. 2,during reservoir gas production, the gas moves toward the wellbore and,at some point, the gas pressure drops below its Dew Point P_(dp),causing retrograde condensation around the wellbore (the formation of aregion of condensate banking around the perforated portions of thewellbore). This formation of liquids with the gas in the formationresults in two-phase flow which has the effect of reducing the apparentpermeability of the formation, and thus reduces the production rate at agiven condition.

FIG. 3 illustrates a well configuration 200, according to the teachingof the present inventions. Wellbore 200 can be drilled usingconventional drilling techniques, for example, directional drillingtechniques or other similar methods. The precise method used is not animportant aspect of the present invention. In one certain exemplaryembodiment, the wellbore 200 is lined with a casing string. The casingstring may then be cemented to the formation. There are a number offactors that go into the decision of whether to case the wellbore 200and whether to cement the casing to the formation. A person of ordinaryskill in the art should know whether the wellbore 200 needs to be cased.In most cases, it will be beneficial to do so.

In the present example, the well 200 has a vertical well portion 202connected to horizontally extending portion 204, extending into ahydrocarbon bearing reservoir or formation 216. In this embodiment, thehydrocarbon is formation gas. The well is cemented and cased 206 andconventionally perforated 208 in the horizontal portion. The toe end ofthe well is plugged by a bridge plug 218, but the toe end of the casingcould be completed as an open hole. Injection tubing 220 is installed inthe casing and is sealed off from the casing at its lower end by apacker 222.

One or more production fractures 210 are formed in or along thehorizontal wellbore portion 204, using a variety of techniques. In oneexemplary embodiment, a plurality of fractures is formed by using ahydra jetting tool, such as that used in the SurgiFrac® fracturingservice offered by Halliburton Energy Services, Inc. in Duncan, Okla. Inthis embodiment, the hydra jetting tool forms each fracture, one at atime. Each fracture may be formed by the following steps: (i)positioning the hydra jetting tool in the wellbore at the location wherethe fracture is to be formed, (ii) perforating the reservoir at thelocation where the fracture is to be formed, and (iii) injecting afracture fluid into the perforation at sufficient pressure to form afracture along the perforation. As those of ordinary skill in the artwill appreciate, there are many variations on this embodiment. Forexample, fracture fluid can be simultaneously pumped down the annuluswhile it is being pumped out of the hydra jetting tool to initiate thefracture. Alternatively, the fracturing fluid may be pumped down theannulus and not through the hydra jetting tool to initiate and propagatethe fracture. In this version, the hydra jetting tool primarily formsthe perforations.

In an embodiment, one or more fractures 210 may be formed by stagedfracturing. Staged fracturing may be performed by a method comprising:(i) detonating a charge in the wellbore at the location where a fractureis to be formed so as to form at least one perforation in the reservoirat that location; (ii) pumping a fracture fluid into the perforation atsufficient pressure to propagate the fracture; (iii) installing a plugin the wellbore uphole of the fracture; (iv) repeating steps (i) through(iii) until the desired number of fractures have been formed; and (v)removing the plugs following the completion of step (iv). As those ofordinary skill in the art will appreciate, there are many variants onthe staged fracture method.

The fractures 210 may take a variety of geometries, but preferably thefractures extend transverse to the wellbore so that the fractures extendat a substantially right angle with respect to the wellbore longitudinalaxis. In some embodiments, the fractures may be formed along naturalfracture lines and may generally be parallel to one another. Thefracture's shape, size and orientation can be determined by theorientation of the fluid nozzles and movement thereof. Usinghydrajetting radially from a vertical wellbore, a transversely extendingfracture can be formed and may extend from about 50 ft to about 1000 ftfrom the wellbore.

One or more barrier perforations 212 and barrier fractures 214 areformed in the horizontal well portion 204. These perforation andfractures are used to form an in-situ barrier may be formed in or alongthe horizontal portion 204 wellbore. The in-situ barrier is disposedwithin the subterranean formation and modifies the flow pattern of atleast one fluid within the subterranean formation. In the illustratedembodiment, one set of fractures 214 is formed on the downhole side ofthe production fractures, and also on the downhole side of injectiontubing 220, packer 222, gas injection 224, injection gas perforation andfrac 226.

According to the present invention, the fracture 214 is opened up toextend from the wellbore. The fracture 214, in this example, isgenerally disk shaped, extending from the wellbore 200 in alldirections. As will be described, fracturing technology exists to createopen fractures from wellbores extending in selected directions,distances and having selected shapes. In an embodiment, the fracture isformed to extend from all sides, about 500 ft. to about 1,000 ft., fromthe wellbore though longer fractures may be possible. In thisembodiment, the fracture 214 is filled with a sealant. The sealant maybe pumped into the fracture 214 as part of a treatment fluid, forexample, in a slurry form and also into any flow paths in the form ofvoids intersecting the fracture 214.

In an embodiment, the sealant used to provide the in-situ barrier may beany material capable of selectively or non-selectively reducing the flowof one or more fluids within a subterranean formation. As used in thiscontext, a non-selective barrier is an in-situ barrier intended tosubstantially seal the fracture. A selective barrier is an in-situbarrier, intended to modify the permeability or relative permeability(as described above) to allow fluids to selectively flow through thefracture. The sealant may comprise a cement, a linear polymer mixture, alinear polymer mixture with cross-linker, an in-situ polymerized monomermixture, a resin-based fluid, an epoxy based fluid, a magnesium basedslurry, a clay based slurry (e.g., a bentonite based slurry), anemulsion, a precipitate (e.g., a polymeric precipitate), or an in-situprecipitate. As used herein, an in-situ precipitate is a precipitateformed within the subterranean formation, for example, using a polymericsolution that is introduced into a subterranean formation followed by anactivator. All of these sealants are capable of being placed in a fluidstate with the property of becoming a viscous fluid or solid barrier tofluid migration after or during placement into the fracture. In oneembodiment, the sealant is H.sub.2Zero™, available from HalliburtonEnergy Services, Inc., Duncan, Okla. Other sealants could includeparticles, drilling mud, cuttings, and slag. Exemplary particles couldbe ground cuttings so that a wide range of particle sizes would existand produce a low permeability as compared to the surrounding reservoir.

As used herein, the term drilling mud includes all types of drilling mudknown to those of ordinary skill in the art including, but not limitedto, oil-based muds, invert emulsions, polymer based muds, clay basedmuds (e.g., bentonite based drilling mud), and weighted muds. In anembodiment, the sealant may comprise swellable particles. As usedherein, a particle is characterized as swellable when it swells uponcontact with an aqueous fluid (e.g., water), an oil-based fluid (e.g.,oil) or a gas. Suitable swellable particles are described in thefollowing references, each of which is incorporated by reference hereinin its entirety: U.S. Pat. No. 3,385,367, U.S. Pat. No. 7,059,415, U.S.Pat. No. 7,578,347, U.S. Pat. App. No. 2004/0020662, U.S. Pat. App. No.2007/0246225, U.S. Pat. App. No. 2009/0032260 and WO2005/116394.

Swellable particles suitable for use with embodiments of the presentinvention may generally swell by up to about 200% of their original sizeat the surface. Under downhole conditions, this swelling may be more, orless, depending on the conditions present. For example, the swelling maybe at least 10% under downhole conditions. In some embodiments, theswelling may be up to about 50% under downhole conditions. Although therate of swelling may be hours in some embodiments, in certainembodiments the rate of swelling may be measured in minutes. The rate ofswelling is defined as the amount of time required for the swelledcomposition to substantially reach an equilibrium state, where swellingis within 5% of its final equilibrium state. However, as those ofordinary skill in the art with the benefit of this disclosure willappreciate, the actual swelling when the swellable particles areincluded in a sealant may depend on, for example, the concentration ofthe swellable particles included in the sealant, the temperature, thepressure, and the other components present in the wellbore.

An example of a swellable particle that may be suitable for use withembodiments of the present invention comprises a swellable elastomerthat swells in the presence of an oil-based fluid or an aqueous-basedfluid. Some specific examples of suitable, swellable elastomers thatswell in the presence of an oil-based fluids include, but are notlimited to: natural rubbers, acrylate butadiene rubbers, isoprenerubbers, chloroprene rubbers, butyl rubbers, brominated butyl rubbers,chlorinated butyl rubbers, chlorinated polyethylenes, neoprene rubbers,styrene butadiene copolymer rubbers, chlorinated polyethylene,sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrinethylene oxide copolymers, epichlorohydrin terpolymer,ethylene-propylene rubbers, ethylene vinyl acetate copolymers,ethylene-propylene-diene terpolymer rubbers, ethylene vinyl acetatecopolymer, nitrile rubbers, acrylonitrile butadiene rubbers,hydrogenated acrylonitrile butadiene rubbers, carboxylatedhigh-acrylonitrile butadiene copolymers, polyvinylchloride-nitrilebutadiene blends, fluorosilicone rubbers, silicone rubbers, poly2,2,1-bicyclo heptenes (polynorbornene), alkylstyrenes, polyacrylaterubbers, such as: ethylene-acrylate copolymer, ethylene-acrylateterpolymers, fluorocarbon polymers, copolymers of poly(vinylidenefluoride) and hexafluoropropylene, terpolymers of poly(vinylidenefluoride), hexafluoropropylene, and tetrafluoroethylene, terpolymers ofpoly(vinylidene fluoride), polyvinyl methyl ether andtetrafluoroethylene, perfluoroelastomers, such as: tetrafluoroethyleneperfluoroelastomers, highly fluorinated elastomers, butadiene rubber,polychloroprene rubber, polyisoprene rubber, polynorbornenes,polysulfide rubbers, polyurethanes, silicone rubbers, vinyl siliconerubbers, fluoromethyl silicone rubber, fluorovinyl silicone rubbers,phenylmethyl silicone rubbers, styrene-butadiene rubbers, copolymers ofisobutylene and isoprene known as butyl rubbers, brominated copolymersof isobutylene and isoprene, chlorinated copolymers of isobutylene andisoprene, and any combination thereof. An example of a commerciallyavailable product comprising such swellable particles may include acommercially available product from Easy Well Solutions of Norway, underthe trade name “EASYWELL.”

Suitable examples of useable fluoroelastomers that swell in the presenceof an oil-based fluid are: copolymers of vinylidene fluoride andhexafluoropropylene and terpolymers of vinylidene fluoride,hexafluoropropylene and tetrafluoroethylene. The fluoroelastomerssuitable for use in the disclosed invention are elastomers that maycomprise one or more vinylidene fluoride units (“VF.sub.2” or “VdF”),one or more hexafluoropropylene units (“HFP”), one or moretetrafluoroethylene units (“TFE”), one or more chlorotrifluoroethylene(“CTFE”) units, and/or one or more perfluoro(alkyl vinyl ether) units(“PAVE”), such as perfluoro(methyl vinyl ether) (“PMVE”),perfluoro(ethyl vinyl ether) (“PEVE”), and perfluoropropyl vinyl ether(“PPVE”). These elastomers can be homopolymers or copolymers.Particularly suitable are fluoroelastomers containing vinylidenefluoride units, hexafluoropropylene units, and, optionally,tetrafluoroethylene units and fluoroelastomers containing vinylidenefluoride units, perfluoroalkyl perfluorovinyl ether units, andtetrafluoroethylene units, such as the vinylidene fluoride typefluoroelastomer, known under the trade designation “AFLAS®,” availablefrom Asahi Glass Co., Ltd. Of Tokyo, Japan. Especially suitable arecopolymers of vinylidene fluoride and hexafluoropropylene units. If thefluoropolymers contain vinylidene fluoride units, the polymers maycontain up to 40 mole % VF.sub.2 units, e.g., 30-40 mole %. If thefluoropolymers contain hexafluoropropylene units, the polymers maycontain up to 70 mole % HFP units. If the fluoropolymers containtetrafluoroethylene units, the polymers may contain up to 10 mole % TFEunits. When the fluoropolymers contain chlorotrifluoroethylene, thepolymers may contain up to 10 mole % CTFE units. When the fluoropolymerscontain perfluoro(methyl vinyl ether) units, the polymers may contain upto 5 mole % PMVE units. When the fluoropolymers contain perfluoro(ethylvinyl ether) units, the polymers may contain up to 5 mole % PEVE units.When the fluoropolymers contain perfluoro(propyl vinyl ether) units, thepolymers may contain up to 5 mole % PPVE units. The fluoropolymers maycontain 66%-70% fluorine. One suitable commercially availablefluoroelastomer is that known under the trade designation “TECHNOFLONFOR HS®,” sold by Ausimont USA, Inc. of Thorofare, N.J. This materialcontains “Bisphenol AF,” manufactured by Halocarbon Products Corp. ofRiver Edge, N.J. Another commercially available fluoroelastomer is knownunder the trade designation “VITON® AL 200,” by DuPont PerformanceElastomers of La Place, La., which is a terpolymer of VF.sub.2, HFP, andTFE monomers containing 67% fluorine. Another suitable, commerciallyavailable fluoroelastomer is “VITON® AL 300,” by DuPont PerformanceElastomers of La Place, La. A blend of the terpolymers known under thetrade designations “VITON® AL 300” and “VITON® AL 600” can also be used(e.g., one-third AL-600 and two-thirds AL-300), both are available fromDuPont Performance Elastomers of La Place, La. Other useful elastomersinclude: products known under the trade designations “7182B” and“7182D,” from Seals Eastern of Red Bank, N.J.; the product known underthe trade designation “FL80-4,” available from Oil States Industries,Inc. of Arlington, Tex.; and the product known under the tradedesignation “DMS005,” available from Duromould, Ltd. of Londonderry,Northern Ireland.

One process for making a swellable elastomer useful in the presentinvention may involve grafting an unsaturated organic acid molecule. Acommon example of an unsaturated, organic acid used for this purpose ismaleic acid. Other molecules that can be used include mono- anddi-sodium salts of maleic acid and potassium salts of maleic acid.Although in principle, other unsaturated carboxylic acids may also begrafted onto commercial, unsaturated elastomers, acids that exist insolid form may not require additional steps or manipulation, as will bereadily apparent to those having reasonable skill in the chemical art.Mixing other unsaturated acids such as acrylic acid and methacrylic acidis also possible but may be more difficult since they are liquids atroom temperature. Unsaturated acids such as palmitoleic acid, oleicacid, linoleic acid, and linolenic acid may also be used. The initialreaction leads to a relatively nonporous, “acid-grafted rubber.” Inorder to enhance the swelling of elastomers, the addition of a smallamount of alkali such as soda ash, along with or separate from theunsaturated acid, leads to formation of a porous, swellable,acid-grafted rubber. Micro-porosities are formed in the composition,allowing a fluid to rapidly reach the interior region of a molded partand increase the rate and extent of swelling. An organic peroxidevulcanizing agent may be employed to produce a vulcanized, porous,swellable, acid-grafted rubber formulation. In one embodiment, 100 phrof EPDM, 5-100 phr of maleic acid, 5-50 phr of sodium carbonate, and1-10 phr of dicumyl peroxide as vulcanizing agent showed at least 150percent swelling of elastomer when exposed to both water at 100° C. for24 hrs. and at room temperature for 24 hrs. in kerosene. Othercommercially available grades of organic peroxides, as well as othervulcanization agents, may be employed. The resulting elastomericcompositions may be described as nonporous, or porous and swelled,acid-grafted rubbers, which may or may not be vulcanized. The terms“vulcanized” and “crosslinked” are used interchangeably herein, althoughvulcanization technically refers to a physicochemical change resultingfrom crosslinking of the unsaturated hydrocarbon chain of polyisoprenewith sulfur, usually with the application of heat. The relativelyhydrophobic linear or branched chain polymers and relatively hydrophilicwater-soluble monomers, either grafted onto the polymer backbone orblended therein, may act together to cost-effectively increase thewater- and/or oil-swellability of oilfield elements that comprise one ormore apparatus of the invention. In particular, the use of unsaturatedorganic acids, anhydrides, and their salts (for example, maleic acid,maleic anhydride, and their salts), offer a commercially feasible way todevelop inexpensive composites materials with good water, and/orhydrocarbon fluid swellability, depending on the type of inorganicadditives and monomers used.

Elastomers such as nitrile rubber, hydrogenated nitrile rubber (HNBR),fluoroelastomers, or acrylate-based elastomers, or their precursors, ifadded in variable amounts to an EPDM polymer or its precursor monomermixture, along with a sufficient amount (from about 1 to 10 phr) of anunsaturated organic acid, anhydride, or salt thereof, such as maleicacid, optionally combined with a sufficient amount (from 1 about to 10phr) of an inorganic, swelling agent, such as sodium carbonate, mayproduce a water-swellable elastomer, having variable low-oilswellability. Addition, to the monomer mixture or to the elastomer afterpolymerization, of a sufficient amount (from about 0.5 to 5 phr) of ahighly acidic unsaturated compound, such as 2-acrylamido-2-methylpropanesulfonic acid (AMPS), results in a water-swellable elastomer havingvariable oil-swellability, and which is further swellable in low pHfluids, such as completion fluids containing zinc bromide. A secondaddition of a sufficient amount (from 1 to 10 phr more than the originaladdition) of inorganic, swelling agent enhances swellability in low pH,high concentration brines. Finally, the addition of a sufficient amount(from 1 to 20 phr), of zwitterionic polymer or copolymer of azwitterionic monomer with an unsaturated monomer, results in across-linked elastomer. The amounts of the various ingredients at eachstage may be varied as suited for the particular purpose at hand. Forexample, if one simply wishes to produce a highly cross-linked,moderately water-swellable (about 100 percent swell) elastomer, havingvery low oil-swellability but very high swellability in low pH fluids,one would use a recipe of 60 to 80 phr of EPDM, and 20 to 40 phr ofnitrile or HNBR, and 4 to 5 phr of AMPS, as well as about 15 to 20 phrof a zwitterionic polymer or monomer.

Another reaction scheme useful in the present invention, enabling alow-cost procedure for making swellable elastomers, involves the use ofAMPS monomer and like sulfonic acid monomers. Since AMPS monomer ischemically stable up to at least 350° F. (177° C.), mixtures of EPDM andAMPS monomer which may or may not be grafted on to EPDM will function asa high-temperature resistant, water-swellable elastomer. The use of AMPSand like monomers may be used in like fashion to functionalize anycommercial elastomer to make a high-temperature, water-swellableelastomer. An advantage of using AMPS is that it is routinely used inthe oilfield industry in loss circulation fluids and is very resistantto downhole chemicals and environments.

Combinations of suitable, swellable elastomers may also be used. Incertain embodiments, some of the elastomers that swell in oil-basedfluids may also swell in aqueous-based fluids. Suitable elastomers thatmay swell in both aqueous-based and oil-based fluids, include, but arenot limited to ethylene propylene rubbers, ethylene-propylene-dieneterpolymer rubbers, butyl rubbers, brominated butyl rubbers, chlorinatedbutyl rubbers, chlorinated polyethylene, neoprene rubbers, styrenebutadiene copolymer rubbers, sulphonated polyethylenes, ethyleneacrylate rubbers, epichlorohydrin ethylene oxide copolymer, siliconerubbers and fluorosilicone rubbers, and any combination thereof. Thoseof ordinary skill in the art, with the benefit of this disclosure, willknow the appropriate fluid to use in order to swell the particularswellable elastomer composition.

In certain embodiments, the swellable elastomers may be crosslinkedand/or lightly crosslinked. Other swellable elastomers that behave in asimilar fashion with respect to fluids may also be suitable. Those ofordinary skill in the art, with the benefit of this disclosure, will beable to select appropriate, swellable elastomers based on a variety offactors, including the application in which the composition will be usedand the desired swelling characteristics.

Where used, the swellable particles generally may be included in theembodiments of the sealant in an amount sufficient to provide thedesired barrier properties. In some embodiments, the swellable particlesmay be placed in a fracture or void in a treatment fluid comprising anamount up to about 50% by volume of the treatment fluid. In someembodiments, the swellable particles may be present in a range of about5% to about 95% by volume of the treatment fluid used to place theparticles.

In addition, the swellable particles that are utilized may have a widevariety of shapes and sizes of individual particles suitable for usewith embodiments of the present invention. By way of example, theswellable particles may have a well-defined physical shape as well as anirregular geometry, including the physical shape of platelets, shavings,fibers, flakes, ribbons, rods, strips, spheroids, beads, pellets,tablets, or any other physical shape. In some embodiments, the swellableparticles may have a particle size in the range of about 5 microns toabout 1,500 microns. In some embodiments, the swellable particles mayhave a particle size in the range of about 20 microns to about 500microns. However, particle sizes outside these defined ranges also maybe suitable for particular applications.

In an embodiment, the sealant may comprise a cement. Any suitable cementknown in the art may be used as the sealant. An example of a suitablecement includes hydraulic cement, which may comprise calcium, aluminum,silicon, oxygen, and/or sulfur and which sets and hardens by reactionwith water. Examples of hydraulic cements include, but are not limitedto, a Portland cement, a pozzolan cement, a gypsum cement, a highalumina content cement, a silica cement, a high alkalinity cement, orcombinations thereof. Preferred hydraulic cements are Portland cementsof the type described in American Petroleum Institute (API)Specification 10, 5th Edition, Jul. 1, 1990, which is incorporated byreference herein in its entirety. The cement may be, for example, aclass A, B, C, G, or H Portland cement. Another example of a suitablecement is microfine cement, for example, MICRODUR RU microfine cement,available from Dyckerhoff GmBH of Lengerich, Germany. Combinations ofcements and swellable particles may also be used.

According to the embodiment of FIG. 3, the flow of hydrocarbon fluidswithin the reservoir is modified through the use of an in-situ barriercomprising a fracture set 214 containing a sealant. The use of anin-situ barrier with selective or non-selective barriers to flow may beused to modify the flow pattern within an entire reservoir. Withoutintending to be limited by theory, it is believed that a plurality ofselectively placed fractures with selective or non-selective barriers tofluid flow may be used to modify the flow regime inside the hydrocarbonreservoir to improve the volumetric sweep efficiency of fluids injectedinto the formation. The flow patterns within a hydrocarbon reservoir maybe determined through the use of a simulator program using any simulatorcapable of calculating the flow regime within a subterraneanenvironment. Suitable simulators for use in hydrocarbon reservoirs areknown to those skilled in the art.

In the FIG. 3 embodiment, one or more gas injection perforations andfractures 226 are formed in the wellbore 200 on the downhole side of thepacker 222, in fluid communication with the tubing 220.

As pointed out previously, if the Dew Point pressure of the reservoirgas P_(dp) is higher than the pressure P_(wf) of the gas 250 flowing inthe annulus, then condensate banking 232 can occur and restrict flow. Aswas previously described, reservoir gas production 217 moves toward thewellbore and, at some point, the gas pressure drops below its Dew PointP_(dp), causing retrograde condensation around the wellbore at 232. Thisformation of liquids with the gas in the formation results in two-phaseflow which has the effect of reducing the apparent permeability of theformation and, thus reduces the production rate at a given condition.

In this embodiment, gas 240 is pumped from the surface, down the tubing217 and into the formation 216 via the fracture 226 at a pressuregreater than the reservoir gas pressure P_(rp). The injected gas 224enters the formation 216 on the downhole side of the barrier fracture214. The barrier fracture 214 prevents the injected gas 224 from flowingalong the wellbore to the production perforations 208. Instead, theinjected gas 224 initially flows radially away from the wellbore andthen over the barrier and into a mixing area 230 where the injected gas224 mixes with the formation gas 217. The injected gas 224 is selected,so that, when it mixes with the reservoir gas 217, the resulting gasmixture has a dew-point pressure equal to or lower than the pressureP_(wf) of the gas 250, flowing in the annulus. In this manner,retrograde condensation around the wellbore at 232 is eliminated, atleast along a portion of the wellbore.

Suitable gasses for reducing the formation gas Dew Point Pressure P_(dp)include methane and carbon dioxide. In the present embodiment, methanegas is stripped from the produced gas at the surface and used as theinjection gas 224.

In FIG. 4, another embodiment of a wellbore assembly 300 according tothe present inventions will be described. Wellbore 302 can be drilledinto and along the wellbore between the boundaries 390 of a hydrocarbonbearing reservoir using conventional drilling techniques, for example,directional drilling techniques or other similar methods.

In the present example, the well 300 has a vertical well portion 304connected to horizontal portion 306, extending into a hydrocarbonbearing reservoir or formation 216. In this embodiment, the hydrocarbonis formation gas. The vertical portion 304 of the well is cemented andcased. The lower horizontal portion 306 is supported in the wellbore 302by external casing packers. In this embodiment, the casing is notcemented in the wellbore 302. A plurality of inflow control devices 312are provided spaced along the horizontal portion 306. In thisembodiment, the control devices 312 are positioned between adjacentexternal packers 310 to control the flow from the formation in the zoneformed between the packers 310. The end of the well casing is open at324. Injection tubing 320 is installed in the casing and is sealed offfrom the casing at its lower end by a packer 322. The lower end of thetubing 320 is open at 224 to one or more gas injection fractures 226.

One or more production fractures 330 are formed in the reservoir atspaced locations along the horizontal portion 306 wellbore. Thefractures 330 are positioned between adjacent external packers 310. Afracture 340 is formed from the wellbore into the formation and filledwith barrier material to form a flow altering barrier 350 in thereservoir.

In this embodiment, gas 370 is pumped from the surface, down the tubing320 and into the formation 390 via the fracture 326. The gas is pumpedinto the formation at a pressure greater than the reservoir gaspressure. The injected gas 370 enters the formation on the downhole sideof the barrier 350. The barrier 350 prevents the injected gas 370 fromflowing along the wellbore to the production perforations 330. Instead,the injected gas 270 initially flows radially away from the wellbore andthen over the barrier and into a mixing area 380 where the injected gas370 mixes with the formation gas 360 to reduce the Dew Point pressure ofthe produced gas.

The inflow control devices 312 regulate the flow along the wellbore toprevent the gas in the formation around the wellbore from dropping belowthe Dew Point Pressure. The interaction of these devices 312 distributesthe gas flow across the wellbore. Devices 312 can be used with gasinjection to maintain the formation fluids at a pressure above the DewPoint Pressure. The devices 312 can also be used for regulatehydrocarbon liquid flow into the wellbore in response to changes inphase of the hydrocarbon flowing through the devices 312.

As used herein the term “inflow control device,” is used to refer toapparatus installed in the well that are capable of controlling the flowof fluids into the wellbore. Inflow control devices include apparatusesthat can vary the flow rate and can either permit or block flow. Inflowcontrol devices 312 ideally suitable for use in this embodiment includeautonomous inflow control devices that operate to control flow based ona characteristic of the produced fluids.

Ideally suited for this use are valves marketed as EquiFlow AutonomousInflow Control Devices. These devices are provided by Halliburton EnergyServices, Inc. These autonomous devices act as valve means forselectively controlling the flow of the multiphase hydrocarbon fluidmixtures into the wellbore while limiting the flow of hydrocarbons inliquid or gas phase, while permitting the flow of hydrocarbon in liquidor gas phase. These devices can autonomously vary the flow ofhydrocarbon mixture into the wellbore in response to changes in thefluid flow in response to changes characteristic of the hydrocarbonmixture, such as hydrocarbon viscosity, hydrocarbon density, and/hydrocarbon flow velocity. These devices can sense these characteristicsto selectively regulate whether gaseous or liquid phase is beingproduced. By controlling formation inflow based on relative phase,pressure of the formation hydrocarbon gas can be maintained above theDew Point during production.

Descriptions of fluid flow control using autonomous flow control devicesand their application can be found in the following U.S. patents andpatent applications, each of which are hereby incorporated herein intheir entirety for all purposes: U.S. patent application Ser. No.12/770,568, entitled “Method and Apparatus for Controlling Fluid FlowUsing Movable Flow Diverter Assembly,” to Dykstra et al., filed Apr. 29,2010; U.S. patent application Ser. No. 12/700,685, entitled “Method andApparatus for Autonomous Downhole Fluid Selection With Pathway DependentResistance System,” to Dykstra et al., filed Feb. 4, 2010 U.S.Publication 2011-0186300; U.S. patent application Ser. No. 12/750,476,entitled “Tubular Embedded Nozzle Assembly for Controlling the Flow Rateof Fluids Downhole,” to Syed et al., filed Mar. 30, 2010; U.S. patentapplication Ser. No. 12/791,993, entitled “Flow Path Control Based onFluid Characteristics to Thereby Variably Resist Flow in a SubterraneanWell,” to Dykstra et al., filed Jun. 2, 2010; U.S. patent applicationSer. No. 12/792,117, entitled “Variable Flow Resistance System for Usein a Subterranean Well,” to Fripp et al., filed Jun. 2, 2010, U.S.Publication 2011/0297384; U.S. patent application Ser. No. 12/879,846,entitled “Series Configured Variable Flow Restrictors For Use In ASubterranean Well,” to Dykstra, filed Sep. 10, 2010, U.S. Publication2012/0060624; U.S. patent application Ser. No. 12/869,836, entitled“Variable Flow Restrictor For Use In A Subterranean Well,” to Holdermanet al., filed Aug. 27, 2010, U.S. Publication 2012/0048563; U.S. patentapplication Ser. No. 12/958,625, entitled “A Device For Directing TheFlow Of A Fluid Using A Pressure Switch,” to Dykstra et al., filed Dec.2, 2010; U.S. patent application Ser. No. 12/966,772, entitled “DownholeFluid Flow Control System and Method Having Direction Dependent FlowResistance,” to Jean-Marc Lopez et al., filed Dec. 13, 2010; U.S. patentapplication Ser. No. 13/084,025, entitled “Active Control for theAutonomous Valve,” to Fripp, filed Apr. 11, 2011; U.S. PatentApplication Ser. No. 61/473,700, entitled “Moving Fluid Selectors forthe Autonomous Valve,” to Fripp et al., filed Apr. 8, 2011; and U.S.patent application Ser. No. 13/100,006, entitled “Centrifugal FluidSeparator,” to Fripp et al., filed May 3, 2011.

In one example, valves are provided that restrict the flow ofhydrocarbon in liquid phase, while permitting the flow of hydrocarbon ingaseous phase into the wellbore. In another example, valves can beprovided that restrict the flow of hydrocarbon in gaseous phase whilepermitting the flow of hydrocarbon in liquid phase into the wellbore. Ina further example, valves can be provided that restrict the flow ofhydrocarbon in dry gaseous phase while permitting the flow ofhydrocarbon in gases in liquid rich phase into the wellbore. In thismanner, the valves can be utilized to control the Dew Point Pressure offormation gas and efficiently produce gas from a retrograde gasformation.

In one embodiment, the valves installed along the wellbore of the typewhich inhibit the inflow of hydrocarbon in liquid form and gas in aliquid rich phase. If the production rate at particular valve causes apressure drop to or below Dew Point Pressure around the wellbore, liquidwill begin to drop out of the produced formation gas. As this occurs,the valve will restrict the production rate to the point where theformation pressure around the wellbore at the valve will rise above theDew Point Pressure, allowing gas phase to be produced.

The inflow control devices inhibit cycling of dry gas while allowingless inhibited flow of liquids rich gas. This prevents undue cycling ofthe dry gas, i.e., preventing production and re-injection of the samegas while improving sweep efficiency of the injected gas. As theformation production continues, the liquids rich gas will be stripped ofliquid hydrocarbons at the surface and the remaining dry gas will beinjected while the liquids are sold off. Eventually, the injected drygas is mixed sufficiently with the liquids rich gas, whereby the DewPoint of the gas mixture in the formation is effectively altered toprevent retrograde condensation. Ultimately, the inflow control devicescan be de-activated to allow unrestricted flow of the formation mixturegas to be produced and sold without further injection or input control.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. While apparatus, compositions andmethods are described in terms of “comprising,” “containing,” or“including” various components or steps, the compositions and methodscan also “consist essentially of” or “consist of” the various componentsand steps. As used herein, the words “comprise,” “have,” “include,” andall grammatical variations thereof are each intended to have an open,non-limiting meaning that does not exclude additional elements or steps.All numbers and ranges disclosed above may vary by some amount. Whenevera numerical range with a lower limit and an upper limit is disclosed,any number and any included range falling within the range isspecifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b,” or, equivalently, “from approximately a-b”) disclosed herein isto be understood to set forth every number and range encompassed withinthe broader range of values. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee. In the claims, the conjunction “and” is inclusive, theconjunction “or” is exclusive and the conjunction “and/or” is eitherinclusive or exclusive. Moreover, the indefinite articles “a” or “an”,as used in the claims, are defined herein to mean one or more than oneof the element that it introduces. If there is any conflict in theusages of a word or term in this specification and one or more patent orother documents that may be incorporated herein by reference, thedefinitions that are consistent with this specification should beadopted.

What is claimed is:
 1. A method of producing hydrocarbons from asubterranean hydrocarbon fluid bearing formation, containinghydrocarbons in a gaseous phase, comprising: providing a wellboreextending into the subterranean hydrocarbon fluid-bearing formation;providing an in-situ barrier, wherein the in-situ barrier is disposedwithin the subterranean formation and modifies the flow pattern of atleast one fluid within the subterranean formation; injecting a fluid ingaseous state from the wellbore into the formation from one side of thebarrier to mix with the formation fluid to form a hydrocarbon mixturewith a lower Dew Point Pressure than the formation hydrocarbon; andflowing hydrocarbon mixture from the formation into the wellbore on theother side of the barrier.
 2. The method of claim 1, wherein theinjected fluid comprises a gas with a Dew Point Pressure that is higherthan the formation gas Dew Point Pressure.
 3. The method of claim 1,wherein the injected fluid is selected from the group, consisting ofmethane and carbon dioxide.
 4. The method of claim 1, additionallycomprising the step of removing the hydrocarbon mixture entering thewellbore, stripping methane gas from the removed hydrocarbon mixture andusing the stripped methane gas in the injecting step.
 5. The method ofclaim 1, wherein the flowing step comprises selectively flowinghydrocarbon fluids in the gaseous phase into the wellbore, whilerestricting the flow into the wellbore of hydrocarbon fluids in theliquid phase.
 6. The method of claim 1, wherein the flowing stepcomprises selectively flowing hydrocarbon fluids in liquid phase intothe wellbore, while restricting the flow into the wellbore of fluids inthe gaseous phase.
 7. The method of claim 1, additionally comprising thesteps of: casing the wellbore; flowing the hydrocarbon mixture into thewellbore at a plurality of locations spaced apart along the wellbore;and controlling the flow of the hydrocarbon mixture into the wellbore atthe plurality of locations by limiting the flow of hydrocarbon in liquidphase, while permitting the flow of hydrocarbon in gaseous phase intothe wellbore.
 8. The method of claim 1, additionally comprising the stepof controlling the flow of the hydrocarbon mixture into the wellbore asa function of the phase of the hydrocarbon mixture.
 9. The method ofclaim 1, wherein the flowing step comprises the step of varying the flowof hydrocarbon mixture into the wellbore in response to changes in thefluid flow characteristic of the hydrocarbon mixture, wherein thecharacteristics are selected from the group consisting of viscosity,density, and velocity.
 10. The method of claim 1, additionallycomprising providing a cased wellbore and a valve controlling the flowinto the wellbore.
 11. The method of claim 1, wherein the in-situbarrier comprises a fracture with a sealant disposed therein.
 12. Themethod of claim 11, wherein the sealant comprises a relative formationpermeability modifier.
 13. The method of claim 1, wherein the flowingstep comprises the step of varying the flow of hydrocarbon mixture intothe wellbore to maintain the flowing hydrocarbon mixture in asubstantially gaseous phase.
 14. The method of claim 1, wherein theflowing step comprises the step of varying the flow of hydrocarbonmixture into the wellbore to maintain the flowing hydrocarbon mixture ina substantially liquid phase.
 15. A subterranean well for producinghydrocarbons from a subterranean formation containing hydrocarbon fluidsin a gaseous phase, comprising: a horizontally extending cased wellboreextending into the subterranean hydrocarbon fluid-bearing formation; thewellbore having separate fluid injection and fluid production pathwaystherein connected to the formation at a longitudinally-spaced locationalong the wellbore; an in-situ barrier, extending generally transverselyfrom the wellbore, wherein the in-situ barrier is disposed within thesubterranean formation and modifies the flow pattern of at least onefluid within the subterranean formation, the barrier being positioned onthe wellbore between the injection and production pathway connections tothe formation; and a valve connected to the wellbore at a subterraneanlocation positioned to control the flow of hydrocarbon fluid into theproduction pathway.
 16. The well of claim 15, wherein the valvecomprises means for varying the fluid flow into the wellbore in responseto changes in the fluid flow characteristic of the hydrocarbon fluid.17. The well of claim 14, wherein the fluid flow characteristics areselected from the group consisting of fluid viscosity, density andvelocity.
 18. The well of claim 15, additionally comprising a pluralityof valves connected to the wellbore at subterranean locations spacedapart along the well to control the flow of hydrocarbon fluid into theproduction pathway.
 19. The well of claim 14, wherein the valveselectively flows fluids in the gaseous phase into the wellbore, whilerestricting the flow into the wellbore of fluids in the liquid phase.20. The well of claim 14, wherein the valve selectively flows fluids inthe liquid phase into the wellbore, while restricting the flow into thewellbore of fluids in the gaseous phase.
 21. The well of claim 13,wherein the in-situ barrier comprises a fracture with a sealant disposedtherein.
 22. The well of claim 19, wherein the sealant comprises arelative formation permeability modifier.